Method for reducing the amount of a sulfur dioxide in a flue gas resulting from the combustion of a fossil fuel

ABSTRACT

A process for removal of sulfur dioxide from a flue gas. An alkaline admixture is coated with a coating agent that improves dispersability and delays calcination of the alkaline admixture within a combustion zone and results in a coated alkaline admixture. The coated alkaline admixture is introduced to the boiler to create a reaction that reduces the amount of sulfur dioxide from the flue gas.

CROSS REFERENCE TO RELATED APPLICATION

This application is a Continuation of Application No. PCT/US2004/16340filed May 25, 2004, which is a PCT application claiming priority ofNonprovisional application Ser. No. 10/756,956, filed Jan. 14, 2004 andProvisional Application filed May 28, 2003; Ser. No. 60/473,689. Thisapplication is a Continuation-In-Part application of Nonprovisionalapplication Ser. No. 10/756,956, filed Jan. 14, 2004 that claims thebenefit of provisional application Ser. No. 60/473,689. This applicationincorporates by reference PCT/US2004/16340 filed May 25, 2004,Nonprovisional application Ser. No. 10/756,956, filed Jan. 14, 2004 andProvisional Application filed May 28, 2003, Ser. No. 60/473,689.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the use of modified alkaline earth oxides andcarbonates for the effective reduction of a pollutant from flue gasresulting from the combustion of fossil fuel.

2. Description of Related Art

Power plants combust fossil fuels in boilers to create steam which is inturn used to power turbine-generators that produce electricity. At thistime nearly one half of the electricity generated in the U.S. resultsfrom the burning of coal. When fossil fuel is combusted in a boiler, thesulfur present in fossil fuel reacts with oxygen to form sulfur dioxide.A small percentage of the resultant sulfur dioxide further reacts withadditional oxygen present in the flue gas of the boiler to form sulfurtrioxide. The combustion of fossil fuel also results in the productionof mercury and arsenic which have deleterious effects upon unitperformance and environmental health.

Traditionally, it has been assumed that approximately one percent of thesulfur contained in fossil fuel exits the combustion chamber as sulfurtrioxide. The sulfur trioxide will react with moisture in the flue gasto form vapor phase sulfuric acid that will condense in the lowertemperature regions of the boiler, more specifically the air heater aswell as equipment farther downstream. Sulfuric acid has been found toform at temperatures less than 500 F. In addition to the substantialincrease in fouling and corrosion to the equipment, the sub-micronsulfuric acid mist that exits the boiler exists as a finely dividedaerosol, which deflects sufficient light in the atmosphere so that avisible “blue plume” becomes observable.

The “blue plume” creates anxiety in the community because everybody isconcerned about the effects of industrial pollution. This situation isexacerbated when the flue gas is passed through a wet flue gasdesulfurization system where the gas temperature is rapidly quenched toa temperature below the acid dew point.

Sulfur trioxide is classified as a Toxic Release Inventory substancetherefore annual emission quantities must be reported to theEnvironmental Protection Agency. It is also very likely that pendingenvironmental regulations will require the capture of very fineparticulate, commonly referred to as “pm 2.5” which includes allparticulate matter as well as condensable materials that are less than2.5 microns in size. Such classification includes sulfuric acid aerosol.Many new construction permits being issued by individual States includecondensable materials in the allowable total particulate emissions.

As would be expected, as the sulfur content in the fuel increases, theamount of sulfur trioxide formed in the boiler increases. Fuelstypically used for the production of steam range from less than onepercent to in excess of four-percent sulfur. Combustion of these fuelswill therefore theoretically produce sulfur trioxide concentrations ofapproximately 5 ppm to 30 ppm, based upon the assumed conversion rate ofone percent. Because of the relatively small concentrations of sulfurtrioxide, little effort had traditionally been made to either measure orcontrol this emission except for units firing costly oil.

Oil used for steam generation is also typically high in vanadium whichincreases the oxidation of sulfur dioxide to sulfur trioxide. The finaltemperature exiting the boiler is controlled such that the gastemperature does not fall below the sulfuric acid dew point. Typicalboiler exit temperatures, downstream of the airheater range from 280 Fto 350 F. Reduction of sulfur trioxide therefore enables lower boilerexit temperatures thus improving the overall thermal efficiency of theunit. The more costly the fuel, the more significant it is to reducesulfur trioxide and lower boiler temperature to create betterefficiency.

Recently promulgated environmental regulations have required substantialreduction of nitrogen oxides from fossil fuel fired boilers. Thepreferred technology for high nitrogen oxide removal from fossil fuelfired boilers is selective catalytic reduction, commonly known as SCR.This technology generally entails the installation of an externalchamber that is equipped with several layers of catalyst. Upstream ofthe catalyst, ammonia is injected and a chemical reaction occurs on thesurface of the catalyst converting the nitrogen oxide and nitrogendioxide to nitrogen and water. A side effect of this technology is thatthe catalyst also oxidizes additional sulfur dioxide to sulfur trioxide.The amount of oxidation is a function of many parameters including thechemical composition of the catalyst as well as factors such as flue gasflow rates, volume of catalyst, temperature, etc. The chemical activityof SCR catalyst is most reactive when initially installed, as it willdeactivate with increased exposure time to the flue gas. The catalystwill generally oxidize anywhere from less than one percent to as much asthree percent of the sulfur dioxide entering the reactor to sulfurtrioxide.

With the increased use of SCR technology because of the recentlypromulgated environmental regulations, an observable increase in theamount of sulfuric acid plume has become evident. While historically fewmeasurements have been made to monitor the amount of sulfur trioxideproduced, the application of SCR technology has resulted in such action.Not only have anticipated oxidation rates been observed across the SCRcatalyst, it has also been confirmed that the assumed boiler conversionrate of one percent can be as much as 50 to 100 percent lower thanactual sulfur trioxide concentrations.

A number of utility companies have been sited by the EPA for violationof opacity limits after the SCR systems have been placed in service.Current regulations require the operation of the SCR systems only duringthe “Ozone Season” which is defined as May 1 through September 30 ofeach year while many of the proposed future environmental regulationswill require 12-month operation. Once year round operation of the SCRbegins, the corrosion and opacity problems will increase proportionally.

In addition to increased sulfur trioxide emissions, a small amount ofammonia passes through the SCR reactor without reacting with thenitrogen compounds. This un-reacted ammonia, commonly referred to as“ammonia slip” is typically anticipated to be less than 2 ppm fortypical coal fired applications; although concentrations as high as 10ppm have been recorded. The ammonia slip readily reacts with sulfurtrioxide to form ammonium bisulfate, when an excess of sulfur trioxideexists, that accumulates on the airheater surfaces. As a result of thisfouling, the heat transfer efficiency deteriorates thus increasing thecost of power production.

At the same time the pressure differential across the airheaterincreases; often, to the extent that the boiler load must be reduced. Ifthe situation is allowed to persist, the unit must reduce load or beshut down to clean the airheater. All of these phenomena result insignificant added cost to the utility operator and reduce unitreliability.

Further, many utilities have also elected to “co-fire” petroleum cokewhich results in even higher levels of oxidation. This occurs becausethe petroleum coke, which can have sulfur content ranging from 4 to 7weight percent sulfur, also can contain between 1000 and 3000 ppmvanadium, which is a very strong oxidant. Field measurements haverecorded sulfur trioxide levels as high as 80 ppm when co-firingpetroleum coke. This practice is currently gaining wide acceptancebecause of economic considerations.

Because of the situation described above, a concerted effort has beenmade by many parties to develop technologies to reduce sulfur trioxide.One of the most comprehensive efforts taken in this regard has beenfunded by the United States Department of Energy. This ongoing programhas examined the introduction of a number of materials into utilityboilers at various locations. This work has included various forms ofseveral alkali's including limestone, lime and magnesium oxide orhydroxide.

Limestone injection into the boiler, while quite effective at removingsulfur trioxide and the least costly additive on a unit basis, wasquickly discarded as a viable technology because of the very high dosagerates required. The required high dosage rates are in the range of astoichiometric ratio of about 40. These high dosage rates of limestonedemonstrated excellent sulfur trioxide capture; however it alsointroduced sufficient calcium to affect boiler eutectics such thatslagging occurred.

Regrettably, while offering the lowest alkali unit cost and the simplestform of introduction, placement on the coal belt, this alternative hasbeen deemed unacceptable because of the slagging. The need for such highdosage rates results from the sintering of the calcium carbonate at thevery high temperatures in the flame region of the boiler which aregenerally in the 2500-3000 F range. The sintering is often referred to“dead burning.”

Other alkalis tested include various forms of magnesium, calcium andsodium. Magnesium may be added as magnesium oxide or magnesiumhydroxide, the latter typically introduced as a slurry while the oxideform is added as a dry powder. Calcium hydroxide has been tested as botha dry powder and as a slurry. Irrespective of the chemical form in whichthese products are added, perhaps the most limiting factor is theability to achieve adequate contact with the sulfur trioxide.

The cross sectional areas of large boilers can exceed 2000 square feet.Injection of a dry powder in the upper region of a boiler, where lowertemperatures are more favorable for alkaline injection, would providevery poor flue gas/additive contact thus reducing the captureefficiency. While these products are capable of producing acceptableresults with respect to sulfur trioxide capture, they require anelaborate and costly injection system and the unit cost per ton ofavailable alkali is significantly higher than limestone. Further,injection into the furnace is subject to wide variability in flue gasflow rates as a function of unit load. The ideal injection point at 100percent load may be poorest at a reduced unit load.

For the optimum system using magnesium, calcium or sodium it istherefore necessary to have a detailed temperature profile for eachboiler over the range of anticipated operating loads. Multiple injectionpoints would be preferred to help offset this impact adding to thecomplexity and cost of such system.

Testing has also been performed with the introduction of various alkaliedownstream of the SCR and upstream of the airheater and electrostaticprecipitator, typically as an aqueous solution. Once again, multiplelances or nozzles must be used to maximize contact with the pollutant.

Perhaps the most comprehensive research effort undertaken to investigatemethods of reducing sulfur trioxide is the ongoing study being performedby the U.S. Department of Energy's National Energy TechnologyLaboratory. The semi-annual report titled “Sulfuric Acid Removal ProcessEvaluation: Short-Term Results”, dated Mar. 4, 2002, as well asfollow-up reports, authored by Gary M. Blyth and Richard McMillan, ofURS Group, the prime contractor for this effort, discusses short termtest results for several alkaline products. Of the many conclusionsincluded in the report, the authors concluded that testing of theinjection of dolomitc limestone through the burners should not becontinued in the long term phase of the program. While the sulfurtrioxide removal efficiencies with the dolomitic limestone were quitegood, the amount required, stoichiometric ratios of approximately 40,and the adverse effects upon boiler operation because of the high dosagerate excluded this technology from further study.

While the study capture of sulfur trioxide is a very current effort,extensive development efforts have been performed in the pastinvestigating furnace injection of limestone for sulfur dioxide control.While many of these efforts were exhaustive in nature, this technologyhas never gained commercial acceptance by the utility industry;primarily because of the low sulfur dioxide removal and the large amountof reagent required.

Landreth, et al, in his U.S. Pat. No. 5,246,364 teaches a method ofinjecting limestone through low NOx burners with mixing of the finelyground limestone with the tertiary air. While the Landreth technology isdesigned to capture a different pollutant, sulfur dioxide, as opposed tosulfur trioxide, his discussion of the impact of sintering of lime isgermane to the teachings herein.

The Lavely U.S. Pat. No. 6,146,607 provides an excellent description ofthe calcinations on limestone. His teaches a method of injectinglimestone into a furnace at a lower temperature range, collecting saidresultant lime and utilizing it for sulfur dioxide capture afterhydration.

BRIEF SUMMARY OF THE INVENTION

An object of this invention is to insert an alkaline admixture into aboiler to reduce the amount of a pollutant in a flue gas withoutslagging the boiler.

An object of this invention is to insert an additive at the most costeffective location but delay reaction of the additive until the additivereaches the best point chemically for the reaction to occur.

Another object of this invention is to be able to insert limestone,quicklime, hydrated lime, lime kiln dust, or blends of the above, toreduce the amount of a pollutant in a flue gas with the fossil fuel forthe boiler but delay calcination until the limestone, quicklime,hydrated lime or lime kiln dust reaches a place in the boiler where thetemperature will not cause said products to sinter.

This invention provides a process for reducing the amount of a pollutantfrom a flue gas resulting from combustion of fossil fuel in a boiler. Analkaline admixture is provided. The alkaline admixture is coated with acoating agent that improves dispersability and delays calcination of thealkaline admixture within a combustion zone and results in a coatedalkaline admixture. In our tests, we used a common siloxane flow aid.Other flow aids which result in improved dispersability and delayedcalcination may also be used. The coating agent can be one of manysiloxane compounds commonly known as flow aid. The coated alkalineadmixture is then introduced to the boiler to create a reaction thatreduces the amount of the pollutant in the flue gas.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a simplified diagrammatic view of a typical boiler showinginjection points; and

FIG. 2 is a simplified diagrammatic view of a typical boiler showinginjection points;

DETAILED DESCRIPTION OF THE INVENTION Definitions

“reducing the amount of a pollutant” refers to actually decreasing theabsolute amount of a particular pollutant which exits the stack.

“pollutant” means an environmental contaminate including but not limitedto arsenic, sulfur trioxide, sulfur dioxide and mercury. It can be anycombination of arsenic, sulfur trioxide, sulfur dioxide and mercury andor other pollutants. It can include a single contaminate or multiplecontaminates.

“flue gas”—the resultant gaseous mixture resulting from the combustionof fossil fuel within the boiler.

“combustion of fossil fuel”—the burning of said fuel which chemically isthe reaction of the fuel with oxygen.

“boiler”—the vessel in which heat is introduced resulting from thecombustion of fuel and steam is produced from water by such heat. Thewater/steam is contained in tubes or pipes within the boiler. Theresultant steam is then often used to turn a turbine/generator whichproduces electricity although in some cases steam is the final product.

“alkaline admixture” as defined herein alkaline admixture refers to amixture of calcium and magnesium compounds including oxides, hydroxidesand carbonates.

“coating agent—includes siloxane compounds and other flow aid productsincluding but not limited, to trimethylsilyl-endblockedpolymethylhydrogensiloxanes, trimethylsilyl-endblockedpolydimethylsiloxanes, and hydroxyl-endblocked polydimethylsiloxanes”

“improves dispersability” refers to the favorable modification of thedistribution of solid particles throughout a gaseous media.

“calcination” the chemical decomposition of calcium carbonate andmagnesium carbonate into their respective oxides and the evolution ofcarbon dioxide gas when exposed to temperatures high enough for saidreactions to occur.

“delays calcination” the slowing down of the chemical reaction whichoccurs when calcium carbonate and magnesium carbonate are exposed toelevated temperatures.

“within a combustion zone” the lower region of the boiler where the fuelis introduced though a series of injection devices commonly referred toas burners.

“introducing the alkaline admixture” the simultaneous injection of fueland admixture into the boiler.

“fossil fuel feed” the energy source which can include coal, petroleumcoke, oil or natural gas.

“physical size”—relative or proportionate dimensions for example thephysical size of the alkaline admixture is greater than 50% minus 200mesh.

“addition rate”—the amount of admixture added to the fuel; generally inthe range of 6 to 15 moles of total alkalinity per mole of sulfurtrioxide removed. This also corresponds to a range of 0.3 to 2.0 weightpercent of the fossil fuel.

DESCRIPTION

FIG. 1 presents a simplified drawing of a typical boiler. Typical alkaliinjection locations are shown at the fossil fuel feed 1, the upperfurnace 2, upstream of the air heater 3 and downstream of the air heater4. The most cost effective injection point is the fossil fuel feed 1.Injection with the fuel also results in excellent mixing. However from achemical perspective the fossil fuel feed 1 is not the best locationbecause the alkaline admixture has to travel through the hightemperature burning zone.

Limestone injection at the fossil fuel feed 1 has been tested by othersand the results were unacceptable because of the high temperature in theburning zone. Temperatures in this region typically exceed 2500 F. Whenlimestone containing calcium carbonate and magnesium carbonate isexposed to temperatures in excess of the respective decompositiontemperatures (2500 F), carbon dioxide is driven off as a gas. Calciumcarbonate decomposes at temperatures in excess of 1400 F and magnesiumcarbonate at approximately 1200 F. As the gas escapes the limestoneparticle, channels are created thus increasing the surface area andreactivity. As the temperature increases above 2200 F the channels beginto fuse together or sinter, commonly known as dead burning. Thisphenomenon is well known and has thoroughly been documented.Differential thermal analysis shows that the calcium carbonate fractionof calcitic limestone begins decomposition at Temperatures as low as1200 F while magnesium carbonates decomposition begins at a lowertemperature of about 925 F.

Because of this limitation with respect to temperature, alkalineinjection typically occurs at the upper furnace 2, upstream of the airheater 3 and downstream of the air heater 4. Injection at theselocations introduces a significant level of complexity as well asuncertainty with respect to good distribution.

In a preferred embodiment of this invention dolomitic materials areused. Such materials contain an equal molar ratio of calcium carbonateand magnesium carbonate. While the decomposition temperature of thecalcium fraction remains unchanged, the magnesium fractionsdecomposition temperature increases by approximately 200 F thus furtherreducing the tendency for sintering.

The degree of calcination is influenced by particle size of thelimestone, temperature and residence time along with other conditionssuch as the partial pressure of carbon dioxide. Labelle et al. in theirU.S. Pat. No. 5,919,038 thoroughly describes the calcination process andthe impact of various parameters. When sintering occurs, the reactivityis significantly reduced. An excellent analogy is that of a sponge whichwill readily absorb many times it's weight in liquid because of thelarge pore volume and surface area. If the sponge is held over an openflame, the pores begin to fuse together thus reducing surface area aswell as total pore volume. After extended exposure to the hightemperature, the sponge looses its ability to absorb liquid.

From a chemical perspective, the ideal location to inject limestone isat the upper furnace 2, because of the lower temperature. However, it isnot very practical because of poor mixing and difficulty in achievinggood distribution across the large cross sectional area of the boiler.Additionally it is expensive to inject the limestone at the upperfurnace 2. An ideal solution would utilize both the cost effectiveinjection of the fossil fuel feed 1 and the best chemical point theupper furnace 2. In order to achieve this, one would have to introducethe limestone with the fuel but delay calcination until the limestonereaches the upper furnace 2 where ideal calcination temperatures exist.The present invention teaches how to accomplish this.

Finely ground limestone, quicklime, hydrated lime, lime kiln dust, orblends of the above are very hydroscopic and therefore has a profoundtendency to agglomerate. By treating the said products with a siloxanecompound, commonly referred to as flow aid, the agglomeration issubstantially reduced. One such product is described by Nicholson inU.S. Pat. No. 4,208,388. While Nicholson readily admits the exactmechanism is unknown, its impact is profound. While the intent ofNicholson's teaching is to enhance the flowability of lime in a bulkphase, such as through a pipe or other conduit, its use in the presentinvention is to increase the quantity of individual particles, presentwhen the lime is introduced into the boiler and provide a coating whichdelays the onset of calcination. The much lower mean diameter of theindividual particles are much more readily carried by the upward flowinggas towards the upper end of the furnace thus reducing residence time.The second advantage of treating the product with a siloxane compound isthat the smaller the particle, the better the distribution across thecross sectional area of the boiler. Production of the treated or coatedadmixture is easily accomplished by adding the appropriate amount offlow aid to alkaline product. Some degree of mixing is required but thiscan easily be accomplished by gradually feeding the flow aid onto thealkaline material as it passes through a screw conveyer. Anotheralternative is load a mixing device with a known quantity of alkalineproduct. To this, the appropriate amount of flow aid is added and themixer is operated for anywhere from 5 minutes to 1 hour. Said mixingdevice could be one of many types commercially available or couldinclude a cement truck or ball mill.

In the preferred embodiment of this invention, the alkaline admixturehaving a coating agent that improves dispersability and delayscalcination of the alkaline admixture within a combustion zone isintroduced into the boiler with the fossil fuel at the fossil fuel feed1. A less attractive, but possible alternative is to pneumaticallyconvey the product to the upper region of the furnace and introducethrough a plurality of nozzles or lances. Once again, the coating agentprovides for greatly enhanced individual particle distribution thusreducing pollutants such as sulfur trioxide, arsenic and mercury.

The preferred alkaline admixture for this process is a byproduct of thelime manufacturing process collected dry downstream of the actualcalcination device or lime kiln; typically in a baghouse and commonlyreferred to as lime kiln dust or LKD. While LKD from both high calciumand dolomitic calcination processes is acceptable, the dolomitic productis preferred because of its high magnesium content. Lime kiln dust iscomprised of very fine lime particles carried by the kiln off gas intothe particulate collection device along with uncalcined limestone.Combustion byproducts from the lime calcining process are also includedin the kiln dust. While coal fired calciners produce usable feedstock,the preferred material would be generated in a gas fired applicationthus eliminating undesired combustion byproducts such as silica, ironand alumina which dilute the efficacy of the product.

LKD byproduct use is preferred however if unavailable, an alkalineadmixture such as CaO, CaCO₃, MgO and MgCO₃ may be produced by mixing ofthe various constituents. The CaO, CaCO₃, MgO and MgCO₃ can each be from10 to 35% by weight of the total weight of the alkaline admixture. Inorder to reduce sulfur dioxide the mixture should have less than 10%Magnesium. The size of the alkaline admixture is preferably greater than50% minus 200 mesh. The alkaline admixture is then coated with asiloxane compound, commonly referred to as flow aid in order to create acoated alkaline admixture. Alternatively, the flow aid material may besimultaneously added during the blending of the various constituents.The amount of siloxane compound used to create the coated alkalineadmixture is from 0.05 to 0.15% percent by weight of the alkalineadmixture.

An example of the use of LKD as the alkaline admixture is illustratedbelow. The LKD was first coated with Flow Aid.

The coated LKD was added to a 540 megawatt utility boiler. Prior toaddition of the coated LKD the sulfur trioxide levels were measured at28 and 30 ppm downstream of the economizer and upstream of the selectivecatalytic reduction system. Downstream of the SCR, the sulfur trioxidelevels were measured at 49 and 68 ppm. After addition of the coated LKDat an addition rate of approximately 1 weight percent of the coal feedrate, the sulfur trioxide level was reduced to levels as low as 5.5 ppm.

Testing conducted on a 650 megawatt boiler demonstrated reductions inboiler sulfur trioxide levels from approximately 20 ppm prior totreatment to 6-8 ppm with addition of the coated LKD.

At a third full scale utility boiler, with a capacity of 620 megawatts,without the SCR in service, sulfur trioxide levels were reduced fromapproximately 19-24 ppm to less than 10 ppm. Most importantly, thevisible “blue plume” typically present at the stack outlet disappearedafter addition of the coated LKD.

An additional advantage of using the technology described herein is theability to remove or complex gaseous phase arsenic upstream of the SCRsystem thus extending the operating life of the catalyst.

Typical fossil fuels fired for the production of steam range from lessthan a few ppm to as high as 80 ppm arsenic. Arsenic is a known materialthat will significantly reduce the operating life of SCR catalyst. Highfuel arsenic content in combination with low free available calciumoxide in the fly ash has been proven to reduce catalyst life by as muchas 50 percent. The addition of limestone into the furnace, although atlower dosages than described herein, is widely practiced throughoutEurope as a means to extend catalyst life. This practice is now employedat several locations throughout the United States. The addition of thealkaline admixture having a coating agent will reduce the amount ofgaseous arsenic in the flue gas.

Alternative technologies which involve injecting alkaline materialsdownstream of the SCR system will require a second alkaline additionsystem to control arsenic if the fuel consumed is high in arsenic.

The combustion of fossil fuel has been identified as a major source ofgaseous mercury emissions. Its detrimental health effects are wellknown, therefore pending legislation will require significant reductionof mercury from flue gas. Over the last decade considerable researchefforts have explored alternative control technologies including but notlimited to the use of activated carbon. Madden, in her U.S. Pat. No.6,528,030 teaches a control technology to capture mercury by way ofalkaline sorbent injection. Her teachings include field test results.The removed mercury is converted to the solid phase and collected in thesolids collection device. It is noteworthy however that her technologyis limited to sorbent injection at temperatures less than 2000 F;presumably a result of the sintering which occurs without treatment astaught herein. Our invention enables the use of the least costly andless intrusive addition of alkaline material directly with the fuel inthe very high temperature combustion zone.

Flyash samples were collected from a 540 mw boiler before and afterinjection of the treated admixture. Prior to injection of our productthe flyash collected had a mercury concentration of 12 ppb. Afterinjection, the mercury concentration in the flyash increased nearlythree fold to 30 ppb. This increase clearly demonstrates that additionalmercury was being converted into the solid phase and collected by theparticulate collection device.

Various changes could be made in the above construction and methodwithout departing from the scope of the invention as defined in theclaims below. It is intended that all matter contained in the abovedescription as shown in the accompanying drawings shall be interpretedas illustrative and not as a limitation.

1. A process for reducing the amount of sulfur dioxide in a flue gasresulting from combustion of fossil fuel in a boiler comprising: (a)providing an alkaline admixture having a coating agent that improvesdispersability and delays calcination of the alkaline admixture within acombustion zone; and (b) introducing the alkaline admixture to theboiler to create a reaction that reduces the amount of the pollutant inthe flue gas.
 2. A process as recited in claim 1 wherein the alkalineadmixture is comprised of CaO, CaCO₃, MgO and MgCO₃.
 3. A process asrecited in claim 2 wherein a physical size of the alkaline admixture isgreater than 50% minus 200 mesh.
 4. A process as recited in claim 2wherein the amount of CaO, CaCO₃, MgO and MgCO₃ are each from 10 to 35%by weight of the total weight of the alkaline admixture.
 5. A process asrecited in claim 1 wherein an amount of the coating agent is from 0.05to 0.15 percent by weight of the alkaline admixture.
 6. The process asrecited in claim 1 wherein the alkaline admixture has at least 5%magnesium by weight of the alkaline admixture.
 7. A process as recitedin claim 1 wherein an amount of coated alkaline admixture is from 2 to15 moles of total alkalinity per mole of sulfur dioxide removed.
 8. Aprocess for reducing the amount of sulfur dioxide from a flue gasresulting from combustion of fossil fuel comprising: (a) providing analkaline admixture having a coating agent that improves dispersabilityand delays calcination of the alkaline admixture within a combustionzone; and (b) adding the alkaline admixture to a fossil fuel feed andthereby introducing the alkaline admixture to the boiler to create areaction that reduces the amount of the sulfur dioxide in the flue gas.9. A process as recited in claim 8 wherein the alkaline admixture iscomprised of CaO, CaCO₃, MgO and MgCO₃.
 10. A process as recited inclaim 8 wherein the amount of CaO, CaCO₃, MgO and MgCO₃ are each from 10to 35% by weight of the total weight of the alkaline admixture.
 11. Aprocess as recited in claim 8 wherein a physical size of the alkalineadmixture is greater than 50% minus 200 mesh.
 12. A process as recitedin claim 8 wherein an amount of the coating agent is from 0.05 to 0.15percent by weight of the alkaline admixture.
 13. A process as recited inclaim 8 wherein the alkaline admixture has at least 5% magnesium byweight of the alkaline admixture.
 14. A process as recited in claim 8wherein an amount of alkaline admixture is from 2 to 15 moles of totalalkalinity per mole of sulfur dioxide removed.
 15. A process as recitedin claim 1 wherein less than 10% of the composition of the alkalineadmixture is magnesium.
 16. A process as recited in claim 8 wherein lessthan 10% of the composition of the alkaline admixture is magnesium.